The present invention relates to methods of treating a subterranean formation, and, at least in some embodiments, to methods of strengthening and improving the conductivity of fractures in subterranean formations having low inherent permeability that comprise tight gas, shales, clays, and/or coal beds.
Subterranean formations comprising tight gas, shales, clays, and/or coal beds generally have a low permeability. As used herein, the term “tight gas” refers to gas found in sedimentary rock that is cemented together so that flow rates are relatively very low. As used herein, the term “shale” refers to a sedimentary rock formed from the consolidation of fine clay and silt materials into laminated, thin bedding planes. As used herein, the term “clay” refers to a rock that may be comprised of, inter alia, one or more types of clay, including, but not limited to kaolinite, montmorillonite/smectite, illite, chlorite, and any mixture thereof. The clay content of the formations may be a single species of a clay mineral or several species, including the mixed-layer types of clay. As used herein, “coal bed” refers to a rock formation that may be comprised of, inter alia, one or more types of coal, including, but not limited to, peat, lignite, sub-bituminous coal, bituminous coal, anthracite, and graphite. Traditionally, these unconventional formations have been viewed as having non-productive rock by the petroleum industry because they are “tight” and have low permeability. Also, they require specialized drilling and completion technologies. Recently, however, there have been a number of significant natural gas discoveries in such formations, which in this economic climate, have warranted production.
Fractures are the primary conduit for the production of oil and gas. In these applications, most of the effective porosity may be limited to the fracture network within the formation, but some gas may have also been trapped in the formation matrix, the various layers of rock, or in the bedding planes. To make these types of formations economical, fracturing/stimulation treatments often are advisable to connect the natural microfractures in the formation as well as create new fractures. Creating or enhancing the conductivity of the formation should increase the production of gas from the formation. In other words, the more surface area that can be exposed within the formation through fracturing the formation, the better the economics and efficiency will be on a given well.
Although the combination of horizontal drilling and hydraulic fracturing has proven to be an effective means to stimulate gas production from some shale reservoirs, the longer term production results are often declining at rates far greater than expected leading to lower ultimate recoveries and questionable economic viability. In some instances, based on initial high productivity, many operators have drilled large numbers of wells only to find that these production rates cannot be maintained at adequate levels for long term economic viability. One cause that has been identified a contributing factor to these rapid declines in well productivity is the inability of such formations to sustain high fracture conductivity under high draw down pressures.
Fracturing such formations is typically accomplished by using linear or crosslinked gels or fresh or salt water fluids comprising a friction reduction additive. These water type fracturing treatments are often referred to as “slick water fracs.” The use of high rate water fracturing techniques has been extensively used in shale stimulations in combination with micro-seismic fracture mapping to try and optimize these stimulation treatments in ultra-low permeability, naturally fractured reservoirs. In such treatments, often the primary objective is to create or connect a complex fracture network, sometimes called a dendritic network, so hydrocarbons may be transported from the reservoir to the well bore in economic quantities. Achieving a highly conductive channel that extends deep into the reservoir along a complex fracture network can be difficult to achieve using conventional techniques. One key problem is that it is difficult to establish a sufficient fracture width in secondary or branch fractures that are perpendicular to the maximum horizontal stress. In this situation, the maximum horizontal stress is acting to restrict the fracture width that can be achieved making it difficult to achieve good proppant placement in these branches. Best results have been observed when fracture mapping indicates the presence of a dendritic network that maximizes the total area of the formation exposed to the fracture.
Conductivity of the fractures may be achieved by placing low concentrations of proppant into the fractures while continuing to inject water at very high flow rates. In many cases, friction reducers are beneficial to maximize the flow rates without exceeding the maximum surface treating pressures. Unfortunately, the combination of low proppant concentrations and low viscosity treatment fluids makes it difficult to achieve good proppant transport in a complex fracture environment. As a result, much of the exposed fracture area may not have sufficient proppant concentration or conductivity to remain in fluid communication with the well bore after the well has been placed on production.
Also problematic in these fractures and fracture networks is the closure/healing of these fractures and or partial or complete proppant embedment resulting from increased closure stress due to high draw down pressures during production as well as potential softening of the formation after exposure to the treatment fluids. Many shales and/or clays are reactive with fresh water, resulting in ion exchange and absorption of aqueous fluids leading to embrittlement of the rock in the formation. The term “embrittlement” and its derivatives as used herein refers to a process by which the properties of a material are changed through a chemical interaction such that a material that originally behaves in a ductile or plastic manner is transformed to a material that behaves in a more brittle manner. Additionally, such degradation may substantially decrease the stability of fractures in the formation, which may cause a decrease in the productivity of the well.
This degradation also leads to proppant embedment. Proppant embedment is believed to cause a reduction in fracture width and conductivity, and may be caused by a compression failure within the fracture. Unlike in well-consolidated formations, proppant embedment in these types of tight formations can be as high as several proppant-grain diameters, e.g., in weakly consolidated sandstones. FIG. 1 illustrates the proppant embedment phenomena. FIG. 2 is a computer screen image illustrating the phenomena. Proppant embedment can reduce fracture width from about 10% to about 60% or more, for example almost 100%, when there is a very low concentration of proppant in the fracture, with subsequent reduction in productivity from oil and gas wells. FIG. 3 illustrates a fracture having near 100% embedment. When this occurs, the pathway for hydrocarbons to the well bore may become obstructed, and production may be impaired.
Clays can swell, disperse, disintegrate or otherwise become disrupted in the presence of foreign aqueous fluids. The swelling or dispersion of clays can significantly reduce the permeability of a formation. The use of salts as formation control additives has not eliminated formation damage as a result of permeability reduction, but can reduce or minimize such damage. A clay which swells is not limited to expanding lattice-type clays but includes all those clays which can increase in bulk volume with or without dispersing, degrading, or otherwise becoming disrupted, when placed in contact with foreign aqueous solutions such as water, and certain brines. Certain clays can also disperse, degrade, or otherwise become disrupted without swelling in the presence of foreign aqueous solutions such as water, certain brines, and emulsions containing water or certain brines. Some clays, in the presence of foreign aqueous solutions, will expand and be disrupted to the extent that they become unconsolidated and produce particles which migrate into a borehole. Formations which consist largely of clay upon absorbing water in a confined space can develop pressures on the order of several thousands of pounds per square inch.
The clay materials defined above occur as minute, plate-like, tube-like and/or fiber-like particles having an extremely large surface area as compared to an equivalent quantity of a granular material such as sand. This combination of small size and large surface area results in a high surface energy with attendant unusual surface properties and extreme affinity for surface-active agents. The structure of some of these clays, for example, montmorillonite, can be pictured as a stack of sheet-like three-layer lattice units which are weakly bonded to each other and which are expanded in the “c” crystallographic direction by water or other substances which can penetrate between the sheets and separate them.
Moreover, the fine aggregate that composes shales and/or clays can pose problems if exposed to high stresses. For example, under high stress, shale can mechanically fail, resulting in the generation of fine clay materials that can be highly mobile in produced fluids. In situations where there is high pore pressure and very little permeability, when the system is exposed to a low pressure environment, the surrounding formation can almost fluidize solid. For example, it is believed that shale, when exposed to high stress and pore pressure conditions, can transform from a solid into a semi-liquid material causing it to intrude into a proppant pack. This can result in shale intrusion, well bore sloughing and large quantities of solids production, plugging screens or filling separators on the surface.
In some formations, the bonding between bedding plane layers may be weaker than the bonding between particles in a given layer. In such formations, the bedding plane may represent a weakness susceptible to mechanical failure or separation. To combat these problems, brines are often used that contain high ion concentration so that ion exchange will not occur and the reactivity of the shales and/or clays will be reduced. In extreme cases, oil-based fluids may be used to avoid exposing the shales and/or clays to aqueous fluids.